Casing annulus tester for diagnostics and testing of a wellbore

ABSTRACT

Embodiments of the present invention generally relate to a casing tester for plugging and abandoning a wellbore. In one embodiment, a method of testing an annulus defined between a first tubular string and a second tubular string includes engaging a first annular packer with an outer surface of the first tubular string and engaging a second annular packer with an outer surface of the second tubular string. The tubular strings extend into a wellbore. The method further includes injecting a test fluid between the packers until a predetermined pressure is exerted on the annulus.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.12/268,748 (Atty. Dock. No. WWCl/0002), filed Nov. 11, 2008, which ishereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to a casing testerfor plugging and abandoning a wellbore.

2. Description of the Related Art

FIG. 1A is a cross section of a prior art sub-sea wellbore 5 drilled andcompleted with a land-type completion 1. A conductor casing string 10may be set from above sea-level 15, through the sea 20, and into thesea-floor or mudline 25. The conductor casing 10 provides formud-returns and allows the wellhead 30 to be located at sea-level 15rather than on the sea-floor 25.

Once the conductor casing 10 has been set and cemented 35 into thewellbore 5, the wellbore 5 may be drilled to a deeper depth. A secondstring of casing, known as surface casing 40, may then be run-in andcemented 45 into place. As the wellbore 5 approaches ahydrocarbon-bearing formation 50, i.e., crude oil and/or natural gas, athird string of casing, known as production casing 55, may be run-intothe wellbore 5 and cemented 60 into place. Thereafter, the productioncasing 55 may be perforated 65 to permit the fluid hydrocarbons 70 toflow into the interior of the casing. The hydrocarbons 70 may betransported from the production zone 50 of the wellbore 5 through aproduction tubing string 75 run into the wellbore 5. An annulus 80defined between the production casing 55 and the production tubing 75may be isolated from the producing formation 50 with a packer 85.

Additionally, a stove or drive pipe may be jetted, driven, or drilled inbefore the conductor casing 10 and/or one or more intermediate casingstrings may be run-in and cemented between the surface 40 and production55 casing strings. The stove or drive pipe may or may not be cemented.

FIG. 1B is a cross section of the completion 1 damaged by a hurricane.Hurricanes in the Gulf of Mexico have recently damaged or destroyedseveral production platforms (not shown) along with the completions 1.The production platforms and the completions 1 have sunk to thesea-floor 25. Many of the wellbores 5 had been in production for manyyears, thereby depleting the formations 50 such that the platformoperators desire to plug and abandon the wellbores 5. To plug andabandon the wellbores 5, the annulus between the surface 40 andproduction 75 casing strings must be tested to ensure integrity of thecement 60 so that hydrocarbons do not leak into the sea 20 and/orsensitive non-hydrocarbon formations, such as aquifers.

SUMMARY OF THE INVENTION

Embodiments of the present invention generally relate to a casing testerfor plugging and abandoning a wellbore. In one embodiment, a method oftesting an annulus defined between a first tubular string and a secondtubular string includes engaging a first annular packer with an outersurface of the first tubular string and engaging a second annular packerwith an outer surface of the second tubular string. The tubular stringsextend into a wellbore. The method further includes injecting a testfluid between the packers until a predetermined pressure is exerted onthe annulus.

In another embodiment, a method of plugging a subsea wellbore having adamaged land-type completion includes cutting a horizontal portion ofthe completion from a vertical portion of the completion. The completionincludes a production casing string, a second casing string adjacent theproduction casing string, and an annulus defined between the casingstrings. The method further includes tier-cutting the vertical portionof the completion into a wedding cake configuration and clamping acasing tester on the wedding cake configuration. The casing testerincludes: a first annular blowout preventer (BOP), a second annular BOP,an inlet, a valve, and a pressure gage. The method further includesengaging the annular BOPs with respective casing strings, therebyisolating the annulus; injecting a test fluid into the inlet; closingthe valve; and monitoring the pressure gage.

In another embodiment, a method of working over, abandoning, orregaining control over a wellbore includes clamping a wellhead on acasing string extending into the wellbore and cemented to the wellbore.The wellhead includes a first annular blowout preventer (BOP), a secondannular BOP, and an outlet. The method further includes engaging thefirst annular BOP with the casing string; running a work string throughthe second annular BOP into the wellbore; engaging the second annularBOP with the workstring; injecting fluid into the wellbore through thework string; and returning fluid from the wellbore through the outlet.

In another embodiment, a method of working over, abandoning, orregaining control over a wellbore includes clamping a wellhead on acasing string extending into the wellbore and cemented to the wellbore,wherein the wellhead comprises a first annular blowout preventer (BOP),a second annular BOP, and an outlet. The method further includesengaging the first annular BOP with the casing string; engaging thesecond annular BOP with a tubular string extending into the wellbore;injecting fluid into the wellbore; and returning fluid from the wellborethrough the outlet.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1A is a cross section of a prior art sub-sea wellbore 5 drilled andcompleted with a land-type completion. FIG. 1B is a cross section of thecompletion damaged by a hurricane.

FIG. 2 illustrates a horizontal portion of the completion severed from avertical portion of the completion, according to one embodiment of thepresent invention. FIG. 2A is plan view of the vertical portion of thecompletion.

FIG. 3 illustrates the vertical portion of the completion tier-cut intoa wedding cake.

FIG. 4 illustrates a casing test assembly installed on the wedding cake.FIG. 4A is a section of an annular BOP. FIG. 4B is a section of thecasing test assembly installed on the wedding cake.

FIG. 5 illustrates the wellbore plugged for abandonment.

DETAILED DESCRIPTION

FIG. 2 illustrates a horizontal portion 1 h of the completion 1 severedfrom a vertical portion 1 v of the completion, according to oneembodiment of the present invention. To begin the plug and abandonmentoperation (P&A), a diver may be dispatched from a salvage vessel (notshown) to the submerged wellhead 30. Alternatively, a remotely operatedvehicle (ROV) (not shown) may be deployed instead of the diver. Thediver may operate valves of the wellhead 30 to bleed pressure from thewellbore 5 and to fill the wellbore 5 with seawater to kill theformation 50. To bleed pressure from the wellbore 5, a line may be runto the salvage vessel to remove built-up hydrocarbons from the wellbore5 so they are not dumped into the sea. Alternatively, a kill fluid, suchas heavy mud, may be injected into the wellhead 30 from the salvagevessel to kill the formation if seawater is insufficient to do so. Ifthe damage to the completion 1 has breached the casings 10, 40, 55, andthe production tubing 75 and/or the wellhead 30, the wellbore 5 mayalready be filled with seawater. The diver may then locate and sever thehorizontal portion 1 h of the completion 1 from the vertical portion 1 vof the completion 1 using a saw (not shown), such as a band saw,reciprocating saw, or a diamond wire saw. The cut may be along thevertical portion 1 v so that the cut is horizontal. The vertical portion1 v may usually be at or near a location where the completion extendsfrom the sea-floor 25 or surface of the earth.

FIG. 2A is plan view of the vertical portion 1 v of the completion 1.Ideally, the casings 10, 40, 60 and the production tubing 75 areconcentrically arranged; however, in practice, an eccentric arrangementis far more likely. The eccentric arrangement may vary from wellbore towellbore and complicates the P&A operation, specifically isolating andtesting the annulus between the surface 40 and production 60 casingstrings.

FIG. 3 illustrates the vertical portion 1 v of the completion 1 tier-cutinto a wedding cake 1 w configuration. The cement 45, 60 levels shownare arbitrary as they may vary from wellbore to wellbore. There may ormay not be cement 45, 60 between respective casings 10, 40, 55obstructing the tier-cut operation. The tier-cut operation may proceedas follows. Holes may then be drilled through the conductor 10 andsurface 40 casings by the diver. Shackles may then be installed by thediver using the holes to secure the casings 10, 40. Two vertical cutsmay be made through the conductor casing 10 by the diver from a top ofthe vertical portion 1 v to the top of the conductor casing 10 shown inFIG. 3. The vertical cuts may be spaced at one-hundred eighty degrees.

A hydraulically-powered cutting tool, such as a port-a-lathe, may thenbe secured to the conductor casing 10 by the diver at or near the top ofthe vertical portion 1 v. The diver may operate the port-a-lathe toradially cut through the conductor casing 10. The diver may thenre-position the port-a-lathe near the top of the conductor casing shownin FIG. 3. The diver may operate the port-a-lathe to again radially cutthrough the conductor casing. The diver may then remove the port-a-latheand the shackles and secure a cable connected to a crane on the salvagevessel to remove the cut portion of the conductor casing 10, therebyexposing the surface casing 40. The operation may then be repeated forthe surface casing 40 and the production casing 55. Before the verticalcuts are made, the diver may water blast the cement 45, 60, ifnecessary. If necessary, the production tubing 75 may simply be cut witha reciprocating saw.

FIG. 4 illustrates a casing tester 400 installed on the wedding cake 1w. The casing tester 400 may include a clamp, such as retention flange402, upper 410 a and lower 410 b annular blowout preventers (BOPs)(i.e., conical or spherical), a spool 404, a valve 406, such as amanually operated gate valve 406, an inlet 407, and a pressure gage 408.The casing tester 400 may be assembled on the salvage vessel or as thetester is being installed on the wedding cake 1 w. The casing tester 400may be longitudinally coupled to the surface casing 40 by the retentionflange 402. The retention flange 402 may include a plurality offasteners, such as retainer screws, that engage an outer surface of thesurface casing 40. The retainer flange 402 may be fastened or welded tothe lower annular BOP 410 b. The lower annular BOP 410 b may be fastenedto the spool 404 by a flanged connection. The upper annular BOP 410 amay be fastened to the spool 404 by a flanged connection. The spool 404may include one or more branches. The valve 406 may be fastened to afirst branch of the spool 404 by a flanged connection. The inlet 407 maybe fastened to the valve 406 by a flanged connection. The inlet 407 mayinclude an end for receiving a hydraulic line, such as a hose, from thesalvage vessel. The inlet end may be threaded. The pressure gage 408 maybe fastened to the second branch by a flanged connection.

FIG. 4A is a cross-section of an annular BOP 410 a′ similar to the firstannular BOP 410 a and usable with the casing tester 400. The secondannular BOP 410 b may be modified by inverting one of the BOPs 410 a,410 a′ and fastening or welding the retention flange 402 onto the bottom(top before inversion). Alternatively, the retention flange 402 may befastened or welded to the upper annular BOP 410 a instead of the lowerannular BOP 410 b so that the casing tester 400 is longitudinallycoupled to the production casing 55 instead of the surface casing 40.Alternatively, a two-piece hinged pipe clamp may be used instead of theretention flange 402.

The annular BOP 410 a′ may include a housing 411. The housing 411 may bemade from a metal or alloy and include a flange 412 welded thereto. Thehousing 411 may include upper and lower portions fastened together, suchas with a flanged connection or locking segments and a locking ring. Apiston 415 may be disposed in the housing 411 and movable upwardly inchamber 416 in response to fluid pressure exertion upwardly againstpiston face 417 via hydraulic port 430 a. Movement of the piston 415 mayconstrict an annular packer 418 via engagement of an inner cam surface422 of the piston with an outer surface of the packer 418. The engagingpiston and packer surfaces may be frusto-conical and flared upwardly.The packer 418, when sufficiently radially inwardly displaced, maysealingly engage an outer surface of a respective one of the casings 40,55 extending longitudinally through the housing 411. In the absence ofany casing disposed through the housing 411, the packer 418 maycompletely close off the longitudinal passage 420 through the housing410, when the packer 418 is sufficiently constricted by piston 415. Upondownward movement of the piston 416 in response to fluid pressureexertion against face 424 via hydraulic port 430 b, the packer 418 mayexpand radially outwardly to the open position (as shown). An outersurface 425 of the piston 416 may be annular and may move along acorresponding annular inner surface 426 of the housing 416. The packer418 may be longitudinally confined by an end surface 427 of the housing411.

The packer 418 may be made from a polymer, such as an elastomer, such asnatural or nitrile rubber. Additionally, the packer 418 may includemetal or alloy inserts (not shown) generally circularly spaced about thelongitudinal axis 440. The inserts may include webs that extendlongitudinally through the elastomeric material. The webs may anchor theelastomeric material during inward compressive displacement orconstriction of the packer 418.

Returning to FIG. 4, the casing tester 400 may be lowered from thesalvage vessel by a crane to the diver. The diver may guide the casingtester 400 onto the wedding cake 1 w and fasten the retention flange tothe surface casing 40. Hydraulic lines may then be connected from thesalvage vessel to the hydraulic ports 430 of the annular BOPs 410 a, b.A testing line may be connected from the salvage vessel to the inlet407. The annular BOPs 410 a, b may then be operated by injection ofhydraulic fluid, such as clean oil, from the salvage vessel throughrespective hydraulic ports 430 until respective packers 418 engagerespective casings 40, 55, thereby isolating the annulus between thesurface 40 and production 60 casing strings. If there is an intermediatecasing string between the surface 40 and production 60 strings, then thetester 400 may be installed on the intermediate and production 60casings since the annulus adjacent the production casing string is influid communication with the formation 50.

Eccentricity of the casings 40, 60, discussed above, does not affectengagement of the pliant packers 418. Testing fluid, such as seawater,may then be injected from the salvage vessel into the inlet 407 untilthe annulus between the surface 40 and production 55 casing strings isat a predetermined test pressure, such as 500 psi. The valve 406 may beclosed by the diver and the diver may monitor the pressure for apredetermined amount of time, such as fifteen minutes, to test theintegrity of the cement 60. If the cement 60 is acceptable, the P&Aoperation may proceed. Alternatively, the valve 406 may be a solenoidvalve operable from the salvage vessel and the pressure gage may be apressure sensor in data communication with the salvage vessel so thatthe test may be monitored and controlled from the salvage vessel.

If the cement 60 is unacceptable, then remedial action may be taken,such as injecting sealant from the salvage vessel into the annulus viathe inlet 407, and then the annulus may be re-tested. The sealant may becement or a thermoset polymer, such as epoxy or polyurethane.

Alternatively, the casing tester 400 may remain on the wedding cake 1 wwhile sealant is injected into the wellbore 5 and up the annulus andthen the annulus may be retested. The production tubing 75 may be usedto inject the sealant.

Alternatively, the production tubing 75 may be removed and a temporarywellhead installed on the wedding cake 1 w for injecting the sealantinto the wellbore and up the annulus. Fluid from the remedial operationmay be returned to the salvage vessel via the inlet 407 (would now be anoutlet). A second casing tester may be used as the temporary wellheadfor repairing the annulus. The second lower BOP may seal against theproduction casing 55 while the second upper BOP may be used to sealagainst a work string run into the wellbore from the salvage vessel,thereby isolating the wellbore. The work string may be may be coiledtubing or drill pipe. The sealant may be injected from the salvagevessel into the wellbore via the workstring.

Alternatively, the casing tester 400 may be adapted to be used on anycasing annulus of the completion 1, such as the conductor casing-surfacecasing annulus. For example, if conductor casing-surface casing annulusis leaking, a larger casing tester may be deployed and installed on thewedding cake 1 w to inject sealant into the annulus and then test theannulus. Alternatively, the leak could be contained and/or discharged tothe salvage vessel via the inlet 407 (would now be an outlet) while theannulus is remedied.

Alternatively, the casing tester 400 may be modified for use on theproduction casing-production tubing annulus 80. The casing tester 400may be used to test the packer 85 or may be used as a temporary wellheadfor conducting remedial operations using the production tubing 75 if thepacker 85 is damaged. The lower BOP 410 b may seal against theproduction casing 55 while the upper BOP 410 a may be used to sealagainst the production tubing 75, thereby isolating the annulus 80.Using the casing tester 400 to seal the annulus 80 may also bebeneficial in an emergency, such as breach of the packer 85. The casingtester 400 may be more quickly installed to contain leakage than asubsea wellhead.

FIG. 5 illustrates the wellbore 5 plugged for abandonment. The casingtester 400 may be removed from the wedding cake 1 w and returned to thesalvage vessel. The production tubing 75 may then be removed from thewellbore. A temporary wellhead may be installed on the wedding cake 1 wfor conducting P&A operations in the wellbore 5. As discussed above, thetemporary wellhead may be a casing tester 400. Returns from the P&Aoperation may flow through the inlet 407 (would now be an outlet) to thesalvage vessel. A work string, such as coiled tubing, may be run intothe wellbore through the wellhead. Sealant may be injected into thewellbore to form a plug 505 and seal the hydrocarbon formation 50. Abridge plug 510 may then be run-in and set. Sealant may be injectedabove the bridge plug 515 to form a second plug 510 and seal any surfaceformations. The temporary wellhead may be removed. The casings 10, 40,and 55 may be cut at a predetermined depth below the mudline 25 and thecut portions removed from the wellbore 5.

Alternatively, instead of plugging and abandoning the wellbore 5, apermanent subsea wellhead may be installed on the wedding cake 1 w and aproduction line run from the wellhead to a new production platform. Theproduction tubing 75 may be left in the wellbore and engaged by the newwellhead or a new string of production tubing and a new packer 85installed.

Alternatively, instead of plugging and abandoning the wellbore 5, atemporary wellhead may be installed on the wedding cake 1 w for workingover or re-completing the wellbore 5, such as perforating anotherhydrocarbon-bearing zone or formation. The casing tester 400 may be usedas the temporary wellhead.

Alternatively, the casing tester 400 may be used on land-based wellboresand other types of sub-sea completions, such as subsea-wellhead typecompletions.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A method of regaining control over a subsea wellbore, comprising:deploying a remotely operated vehicle (ROV) to a wellhead of the subseawellbore, wherein a first tubular string extends from the wellhead;severing an upper portion of the first tubular string from a lowerportion of the first tubular string, wherein the first tubular string issevered above the wellbore; clamping a temporary wellhead to an outersurface of the first tubular string, wherein: the temporary wellheadcomprises a first annular blowout preventer (ABOP), a clamp connected tothe first ABOP by a flanged connection, and a spool connected to thefirst ABOP by a flanged connection, and the temporary wellhead isclamped on the first tubular string above the subsea wellbore andadjacent to a sea-floor; and engaging the first annular BOP with thefirst tubular string outer surface, thereby containing leakage from thesubsea wellbore.
 2. The method of claim 1, wherein: the first tubularstring is an outer tubular string, the temporary wellhead furthercomprises a second ABOP connected to the spool by a flanged connection,and the method further comprises engaging the second ABOP with an outersurface of an inner tubular string, and the inner tubular string extendsinto the wellbore.
 3. The method of claim 2, wherein: an upper portionof the inner tubular string is also severed when the outer string upperportion is severed, the method further comprises cutting and removing aportion of the lower outer tubular string portion to expose acorresponding portion of the inner tubular string lower portion, therebyforming a wedding cake configuration, and the second ABOP is engagedwith the exposed portion of the inner tubular string.
 4. The method ofclaim 2, further comprising removing the inner tubular string from thewellbore.
 5. The method of claim 2, further comprising: injectingsealant into the wellbore, thereby plugging the wellbore; and removingthe temporary wellhead from the wellbore.
 6. The method of claim 1,wherein: the temporary wellhead has an outlet, and the method furthercomprises discharging fluid from the wellbore through the outlet.
 7. Themethod of claim 1, wherein: the temporary wellhead further comprises avalve and a pressure gage, and the method further comprises closing thevalve and monitoring the pressure gage.
 8. The method of claim 1,wherein: the temporary wellhead has an inlet, and the method furthercomprises injecting fluid into the subsea wellbore via the inlet.
 9. Themethod of claim 8, wherein the fluid is sealant.
 10. The method of claim9, wherein the sealant is cement.
 11. The method of claim 1, wherein:the wellbore extends into a hydrocarbon bearing formation, and themethod further comprises injecting sealant into the subsea wellbore toseal the formation.
 12. The method of claim 11, further comprising:setting a bridge plug in the wellbore; and injecting the sealant abovethe bridge plug.
 13. The method of claim 1, wherein the first tubularstring is severed adjacent to the sea-floor.
 14. The method of claim 1,wherein the wellhead is a subsea wellhead.
 15. The method of claim 1,wherein the first tubular string is severed using the ROV.